Hydraulic fracturing of conventional oil- and gas-bearing formations requires the high-pressure injection of a fracturing fluid from the well into the formation. During this process, the rock will fail, forming a crack or fracture. This occurs when the surface pumping pressure plus the hydrostatic pressure of the fluid in the wellbore less the friction loss from flow of the fluid through pipe and perforations exceeds the formation stresses.
The direction of the fracture created using conventional fracturing techniques is away from the wellbore in a bi-wing manner and perpendicular to the formation's least principle stress. The fracture growth in bi-wing fractures continues as the pressure and the fluid rate entering the fracture are greater than the fluid lost to the formation from the fracture. Once fracture growth is initiated, small amounts of proppants, such as well-rounded sand, having sizes ranging from 70/140 to 16/20 mesh may be added to the fluid. Normally, the amount of proppant per gallon of fluid increases as the treatment progresses.
The fracturing fluid is normally a high-viscosity fluid that can be described as a gel or semi-solid. It is based on a gelling agent such as guar gum that is crosslinked with chemicals like borate ion, zirconium and titanium chelates such as zirconium lactate and zirconium lactate triethanolamine. The viscosity can range from 200 to 2000 cP at 40 sec−1, but typically ranges from 400 to 1000 cP at 40 sec−1. The viscosity is needed to create fracture width and to carry the proppant deep within the fracture.
Conventional fracturing techniques are, however, often not acceptable in the fracturing of shale and tight gas formations exhibiting a permeability less than 10 mD and in some cases lower than 1.0 mD and often lower than 0.1 mD. (Permeability is a measure of the resistance of flow in porous materials like sedimentary formation rock.) Whereas conventional reservoirs require the creation of bi-wing fractures, the fracturing of low permeability formations, such as shale, requires maximizing complex fracture development, or the creation of secondary and tertiary fractures forming off from the primary fracture. Two factors promote fracture complexity. First, that the fracturing fluid be pumped at a high rate. Second, that the fracturing fluid be a very thin fluid.
While slickwater fracturing has become a preferred fracturing fluid in the treatment of low permeability reservoirs, it has major drawbacks. Slickwater fluids are normally composed of water and 0.25 to 2.0 gal/1000 gal water of a friction reducer. The friction reducers are normally added to water as invert polymer emulsions based on anionic or cationic polyacrylamide. The low viscosity fluid does not allow adequate proppant transport in the fracture, nor does it create enough fracture width to fill the fracture with higher loadings of larger-sized proppant. Slickwater fracturing is thus more suitable for high mobility gas, where lesser amounts of proppant are required. For oil, which is less mobile than gas, the proppant has to be of a larger size and wider fractures are needed to adequately drain the reservoir. This is currently accomplished by the sequential pumping of slickwater followed by conventional high viscosity fluids, neither fluid having the ideal characteristics to hydraulically fracture a shale reservoir.
Alternatives have been sought for low viscosity fluids which enhance the creation of a fracture network in low permeability reservoirs and which provide enhanced proppant transport into the created fractures.